Note: Descriptions are shown in the official language in which they were submitted.
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METHODS AND COMPOSITIONS FOR TREATING SUBTERRANEAN
FORMATIONS WITH SWELLABLE LOST CIRCULATION MATERIALS
BACKGROUND
[0001] The present invention relates to methods and compositions for
treating subterranean formations with swellable lost circulation materials.
[0002] Hydrocarbon producing wells are typically formed by drilling a
wellbore into a subterranean formation. A drilling fluid is circulated through
a
drill bit within the wellbore as the wellbore is being drilled. The drilling
fluid is
produced back to the surface of the wellbore with drilling cuttings for
removal
from the wellbore. The drilling fluid maintains a specific, balanced
hydrostatic
pressure within the wellbore, permitting all or most of the drilling fluid to
be
produced back to the surface. However, the hydrostatic pressure of the
drilling
fluid may be compromised if the drill bit encounters certain unfavorable
subterranean zones, such as low pressure zones caused by natural fissures,
fractures, vugs, or caverns, for example. Similarly, if the drill bit
encounters
high pressure zones, crossflows or an underground blow-out may occur. The
compromised hydrostatic pressure of the drilling fluid causes a reduction of
drilling fluid volume returning to the surface, termed "lost circulation." In
addition to drilling fluids, other operational treatment fluids, such as
fracturing
fluid, may be lost to the subterranean formation due to fluid loss. The term
"lost
circulation" refers to loss of a drilling fluid, while the term "fluid loss"
is a more
general term that refers to the loss of any type of fluid into the formation.
As a
result, the service provided by the treatment fluid is often more difficult to
achieve or suboptimal.
[0003] The consequences of lost circulation or fluid loss can be
economically and environmentally devastating, ranging from minor volume loss
of treatment fluids, to delayed drilling and production operations, to an
underground well blow-out. Therefore, the occurrence of lost circulation or
fluid
loss during hydrocarbon well operations typically requires immediate remedial
steps. Remediation often involves introducing a composition into the wellbore
to
seal unfavorable subterranean zones and prevent leakoff of the treatment
fluids
within the formation to unfavorable zones ("fluid loss zones").
Such
compositions are generally referred to as "fluid loss control materials" or
"FLCM."
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[0004] Typical FLCMs are roughly spherical, having a sphericity of about
0.7 to about 1, and formed from cementitious material, flexible polymeric
material, or naturally occurring materials (e.g., nut shell pieces or
cellulosic
materials), for example. In some cases, multiple FLCM types are mixed and
used together to treat fluid loss in order to gain the functional benefit of
each
type.
[0005] Traditional FLCMs, however, may only partially seal a fluid loss
zone, particularly when the fluid loss zone is a large cavernous or vugular
zone.
Multiple factors may affect the success of a fluid loss control operation,
including, but not limited to, the wellbore size, the wellbore depth, the
types of
treatment fluids used, the drill bit nozzle size, and the FLCM shape and size.
For
instance, a particular sized and shaped FLCM may be required to adequately
treat a formation, but is of such a size and shape that it interferes with the
pumpability of the operational fluid into the wellbore, causing potential
damage
to drilling equipment and delay. Additionally, traditional FLCMs may form
insufficient contact among one another to withstand stresses within the
subterranean formation (e.g., the stresses of formation itself, the fluid loss
zone,
other FLCM particulates, the stress of flowing treatment fluids, and the
like).
Traditional FLCMs may also fail to interact with one another to sufficiently
prevent treatment fluids from leaking-off into a formation due to the presence
of
interstitial spaces between aggregated individual FLCMs. This may be
particularly so if the FLCMs are of similar shapes and sizes. Moreover, the
presence of such interstitial spaces may result in a widening of the
interstitial
spaces as fluid flows through, thereby compounding the fluid loss problem.
Accordingly, an ongoing need exists for methods and compositions of blocking
the flow of fluid through fluid loss zones in a subterranean formation.
BRIEF DESCRIPTION OF THE FIGURES
[0006] The following figures are included to illustrate certain aspects of
the present invention, and should not be viewed as exclusive embodiments. The
subject matter disclosed is capable of considerable modifications,
alterations,
combinations, and equivalents in form and function, as will occur to those
skilled
in the art and having the benefit of this disclosure.
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[0007] FIG. 1A and 16 show a crescent-shaped swellable particle
formed from coextrusion of a nonswellable polymer and a swellable polymer of
the present invention in its initial unswelled rectangle-shape (FIG. 1A) and
its
swelled crescent-shape (FIG. 16).
[0008] FIG. 2A and 2B show a star-shaped swellable particle formed
from coextrusion of a nonswellable polymer and a swellable polymer of the
present invention in its initial unswelled star-shape (FIG. 2A) and its
swelled
star-shape (FIG. 26).
[0009] FIG. 3A and 36 depict a crescent-shaped swellable particle
formed from coextrusion of a nonswellable polymer and a swellable polymer of
the present invention in its initial unswelled cylinder-shape (FIG. 3A) and
its
swelled crescent-shape (FIG. 3B).
[0010] FIG. 4A, 46, 4C, and 4D show a hollow, flexible member with at
least one closed end (FIG. 4A), having a swellable particle placed within such
that it substantially abuts the at least one closed in (FIG. 46), where the
hollow,
flexible member is collapsed (FIG. 4C) around the swellable particle (FIG.
4D).
[0011] FIG. 5 depicts a crescent-shaped hollow, flexible member after a
swellable particle has been placed therein and has swelled.
[0012] FIG. 6 shows a cylinder-shaped hollow, flexible member after a
swellable particle has been placed therein and has swelled.
DETAILED DESCRIPTION
[0013] The present invention relates to methods and compositions for
treating subterranean formations with swellable lost circulation materials.
[0014] The present invention provides for methods of effectively
plugging fluid loss zones using swellable FLCMs that do not cause pumping
problems during hydrocarbon well operations. The methods taught in this
disclosure use swellable FLCMs having various shapes that are capable of
themselves swelling and sealing a fluid loss zone alone or that capable of
interacting with one another so as to create an entangled mass. As used
herein,
the term "entangled mass" refers to the overlapping or intertwining of at
least a
portion of a first swellable FLCM of the present invention with at least a
portion
of a second swellable FLCM of the present invention. The swellable FLCMs alone
or the entangled mass of swellable FLCMs of the present invention may not only
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serve to control fluid loss, but may also serve as consolidating materials,
capable
of trapping loose material in the subterranean formation (formation fines),
for
example. As used herein, the term "consolidating material" refers to a
material
capable of controlling the undesireable production of materials (e.g.,
formation
fines) to the surface during hydrocarbon well production.
[0015] In some embodiments, the present invention provides for
method of treating a fluid loss zone in a wellbore in a subterranean formation
with swellable particles. The swellable particles have an initial unswelled
volume
and a pre-defined shape. Upon introducing the swellable particles into a
subterranean formation, the swellable particles swell to adopt a swelled
volume
larger than the unswelled volume and the pre-defined shape, so as to seal at
least a portion of the fluid loss zone.
[0016] The swellable particles of the present invention may be of any
material capable of swelling upon introduction into a subterranean formation,
so
long as the material does not interfere with the methods of the present
invention. In preferred embodiments, the swellable particles of the present
invention are formed from a swellable polymer or a salt of swellable polymeric
material. Suitable examples of swellable polymers that may form the swellable
particles of the present invention include, but are not limited to, cross-
linked
polyacrylamide; cross-linked polyacrylate; cross-linked copolymers of
acrylamide
and acrylate monomers; starch grafted with acrylonitrile and acrylate; cross-
linked polymers of two or more of allylsulfonate; 2-acrylamido-2-methyl-1-
propanesulfonic acid; 3-allyloxy-2-hydroxy-1-propanesulfonic acid; acrylamide,
acrylic acid monomers; and any combination thereof in any proportion. Suitable
examples of salts of polymeric material that may form the swellable particles
of
the present invention include, but are not limited to, salts of carboxyalkyl
starch;
salts of carboxymethyl starch; salts of carboxymethyl cellulose; salts of
cross-
linked carboxyalkyl polysaccharide; starch grafted with acrylonitrile and
acrylate
monomers; and any combination thereof.
An example of a suitable
commercially available swellable polymer that may form the swellable particles
of the present invention includes, but is not limited to, DIAMOND SEAL ,
available from Halliburton in Houston, TX. The specific features of the
swellable
particles of the present invention may be chosen based on the type and
conditions of the subterranean formation being treated, the size and porosity
of
the fluid loss zone to be treated, and the like.
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[0017] In some embodiments, the swellable particles may be comprised
of a coextruded polymer or salt of polymeric material. As used herein, the
term
"coextruded" refers to the extrusion of multiple layers of a polymer or salt
of
polymeric material simultaneously. For example, in some embodiments, a
polymer or salt of polymeric material with more tensile strength may be used
as
an outer, shape-defining material and a more flexible polymer or salt of
polymeric material may be used as the inner core. In other embodiments, a
polymer or salt of polymeric material with more tensile strength may be used
as
the inner core and a more flexible polymer or salt of polymeric material may
be
used as the outer core. In still other embodiments, a non-swelling polymer may
be coextruded with the swellable particles of the present invention. By way of
nonlimiting example, a non-swellable polymer may be coextruded so as to flank
a swellable particle of the present invention, such that the swellable
particle has
a non-swellable polymer surrounding it. In these cases, the swellable particle
is
typically non-spherical or the coextrusion is asymmetric, which facilitates
curing
of the swellable particle while maintaining adequate stiffness. Polymers that
are
substantially nonswellable or nonswellable may be of any polymer known in the
art suitable for use in a subterranean operation. Suitable nonswellable
polymers
may include, but are not limited to, polyurethane; carboxylated butadiene-
styrene rubber; polyester; polyacrylate; and any combination thereof. One of
ordinary skill in the art, with the benefit of this disclosure, will know what
nonswellable polymer to use in the methods of the present invention given a
particular application.
[0018] The swellable particles of the present invention are capable of
swelling upon contact with a swelling agent. The swelling agent for the
swellable
particulate can be any agent that causes the swellable particulate to swell
via
absorption of the swelling agent. The swelling agents for use in combination
with the swellable particles of the present invention may be water-swellable;
oil-
swellable; or a combination thereof. In a some embodiments, the swellable
particle is "water swellable," meaning that the swelling agent is water. The
term
"water-swellable" encompasses swellable particles that swell upon contact with
an aqueous fluid, but only if the aqueous fluid possesses a particular
property
(e.g., a particular salinity, temperature, pH, and the like). Suitable sources
of
water for use as the swelling agent include, but are not limited to, fresh
water;
brackish water; seawater; brine; and any combination thereof. In another
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embodiment of the invention, the swellable particle is "oil swellable,"
meaning
that the swelling agent for the swellable particle is an organic fluid. The
term
"oil-swellable" encompasses swellable particles that swell upon contact with
an
organic fluid, but only if the organic fluid possesses a particular property
(e.g., a
particular type of hydrocarbon, temperature, and the like). Examples of
organic
swelling agents include, but are not limited to, diesel; kerosene; crude oil;
synthetic oil; and any combination thereof.
[0019] The swellable particles are introduced into a subterranean
formation during a hydrocarbon well operation prior to swelling. That is, they
have an unswelled volume. Typically, the unswelled volume of the swellable
particles of the present invention is less than about 15 mm in diameter. The
unswelled volume is of a size such that it does not produce pumping problems
when pumped into a subterranean formation in high concentrations. Upon
swelling, the swellable particles may increase in size up to about four times
(or
400%) the unswelled volume. In some embodiments, it may be preferred that
the swellable particles swell less than four times the unswelled volume (e.g.,
350%, 300%, 250%, 200%, 150%, 100%, or 50%, for example).
[0020] The swellable particles of the present invention may have a pre-
determined shape or may be capable of forming to the shape of a confined area
in which the swelled particle is confined upon swelling. In those embodiments
where the swellable particles have a pre-determined shape, the shape may or
may not be evident prior to swelling. That is, if the shape of the swellable
particle is cross-shaped, prior to swelling the swellable particle may exhibit
some
other shape, such as a pellet shape, for example. Suitable shapes that the
swellable particles of the present invention may adopt at least in their
swelled
volume include, but are not limited to, spherical-shaped; cubic-shaped; rod-
shaped; rectangle-shaped; cone-shaped; ellipse-shaped; cylinder-shaped;
polygon-shaped; pyramid-shaped; torus-shaped; cross-shaped; lattice-shaped;
star-shaped; crescent-shaped; bowtie-shaped; semicircle-shaped; spiral-
shaped; and any combination thereof. The shape of the swelled swellable
particle may be selected based on the fluid zone to be controlled. For
example,
for large vugular fluid loss zones, it may be preferred to select a high
concentration of long, slender shaped swellable particles, such as crescent-
shaped swellable particles, that may act only or interact with one another so
as
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to form a complex entangled mass. In other embodiments, swellable particles
that are substantially spherical may be preferred.
[0021] In those embodiments where the swellable particle has a
predefined shape, it may be preferable to use the coextruded swellable
particles
of the present invention to define or control that shape. The coextruded
swellable particles may be coextruded with other swellable particles or with
substantially nonswellable or nonswellable polymers.
[0022] Referring now to the figures, in Figure 1A, crescent-shaped
swellable particle 10 is shown in its rectangle-shaped unswelled form 15. Non-
swellable polymer 25 flanks swellable particle 30 of the present invention.
Figure 1B shows the crescent-shaped swelled form 20 of crescent-shaped
swellable particle 10, where the crescent-shape is due to the swelling of
swellable particle 30, which contorts or bends non-swellable polymer 25.
[0023] In Figure 2A, star-shaped swellable particle 40 is shown in its
unswelled form 45. Non-swellable polymer 55 forms the outer core of the
unswelled form 45 of star-shaped swellable particle 40 and swellable particle
60
forms the inner core 65 of the unswelled form 45 of star-shaped swellable
particle 40. Figure 2B shows the star-shaped swelled form 50 of star-shaped
swellable swellable particle 40 after swelling particle 40.
[0024] In Figure 3A, crescent-shaped swellable particle 60 is shown in
its cylinder-shaped unswelled form 65.
Non-swellable polymer 75 flanks
swellable particle 80 of the present invention. Figure 3B shows the crescent-
shaped swelled form 70 of crescent-shaped swellable particle 60, where the
crescent-shape is due to the swelling of swellable particle 80, which contorts
or
bends non-swellable polymer 75.
[0025] In those embodiments where the swellable particles of the
present invention conform to the shape of a confined area in which they are
confined, the swellable particles may be included within a hollow, flexible
member so as to completely fill the hollow, flexible member.
In other
embodiments, it may be preferred that the swellable particle only fill a
portion of
the hollow, flexible member. This may be preferred so as to utilize the non-
filled
portion of the hollow, flexible member as an agent to encourage interaction
among individual encased swelled fluid loss particles or other particulates.
In
still other embodiments, the hollow, flexible member may itself expand (i.e.,
due
to the nature of the material forming the hollow, flexible member) so as to
allow
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the swellable particle to fully swell. The preferred swelled volume may be
dependent upon, for example, the size and shape of the targeted fluid loss
zone.
[0026] In some embodiments, the present invention provides a method
of treating a fluid loss zone in a wellbore in a subterranean formation
comprising
providing a hollow, flexible member having at multiple ends and a shape and a
swellable particle having an initial unswelled volume. The swellable particle
is
placed into a first portion of the hollow, flexible member, while leaving a
second
portion empty. Next, the second portion of the hollow, flexible member is
collapsed around the swellable particle and form a collapsed swellable
particle
having a volume approximately equivalent to the initial unswelled volume of
the
swellable material. The collapsed swellable particle is then introduced into
the
wellbore in the subterranean formation and the swellable particle is swelled
so as
to adopt a swelled volume beyond the initial unswelled volume and take the
shape of the hollow, flexible member so as to form an encased swelled fluid
loss
particle and seal at least a portion of the fluid loss zone.
[0027] In preferred embodiments, the hollow, flexible member has a
pre-defined shape and a swellable particle is placed within the hollow,
flexible
member such that when the swellable particle swells, it fills the space of the
hollow, flexible member so as to take on its shape. The hollow, flexible
member
may also serve to limit the swelling of the swellable particle. Typically, the
swellable particle placed into a hollow, flexible member does not have a
specific
shape that it forms when it is swelled. Rather, it is capable of conforming to
the
shape of the hollow, flexible member.
[0028] In some embodiments, the hollow, flexible member may have
multiple ends and the swellable particle is placed substantially in the center
of
the hollow, flexible member. In other embodiments, the hollow, flexible
member may have multiple ends with at least one closed end. Referring now to
the figures, FIG. 4A shows hollow, flexible member 20 with closed end 25. In
FIG. 4B, swellable particle 30 having an unswelled volume and is placed into
the
first portion 35 of hollow, flexible member 20, substantially abutting closed
end
25, and a second portion 40 of hollow, flexible member 20 does not house
swellable particle 30. In FIG 4C, the second portion 40 of hollow, flexible
member 20 is collapsed, and, as shown in FIG. 4D, the collapsed hollow,
flexible
member 20 surrounds the swellable particle 30 and form collapsed swellable
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particle 45 having substantially the same volume as the unswelled volume of
swellable particle 30.
[0029] Like the swellable particles of the present invention, the hollow,
flexible members of the present invention may have a predetermined shape
which is manifested upon placing a swellable particle into the hollow,
flexible
member and swelling the swellable particle. Suitable shapes that the hollow,
flexible member of the present invention may include, but are not limited to,
spherical-shaped; cubic-shaped; rod-shaped; rectangle-shaped; cone-shaped;
ellipse-shaped; cylinder-shaped; polygon-shaped; pyramid-shaped; torus-
shaped; cross-shaped; lattice-shaped; star-shaped; crescent-shaped; bowtie-
shaped; semicircle-shaped; spiral-shaped; and any combination thereof. The
shape of the hollow, flexible member may be selected based on the fluid loss
zone to be controlled. For example, for large vugular fluid loss zones, it may
be
preferred to select a high concentration of long, slender shaped hollow,
flexible
member, such as crescent-shaped hollow, flexible member, that may act alone
or may interact with each other so as to form a complex entangled mass. Figure
5 demonstrates such crescent-shaped hollow, flexible members after the
swellable particle has been placed within the hollow, flexible member and has
swelled. Collapsed swellable particles 105 comprise swellable particles 115
within crescent-shaped hollow, flexible members 110. Upon swelling the
swellable particles, they take the shape of the cresent-shaped hollow,
flexible
members 110 to form encased swelled fluid loss particles 115, which interact
to
form entangled mass 120. In other embodiments, hollow, flexible members
that are substantially spherical may be preferred. In still other embodiments,
hollow, flexible members that are cylinder-shaped, as shown in Figure 6 are
preferred. Collapsed swellable particles 205 comprise swellable particles 215
within cylinder-shaped hollow, flexible members 210.
Upon swelling the
swellable particles, they take the shape of the cylinder-shaped hollow,
flexible
members 210 to form encased swelled fluid loss particles 225, which interact
to
form entangled mass 220.
[0030] The hollow, flexible members of the present invention may be
formed from any material capable of use in a hydrocarbon well operation,
capable of flexibility, and capable of allowing a swelling agent to pass
through
and contact the swellable particle therein. In some preferred embodiments, the
hollow, flexible members are permeable so as to facilitate contact with a
swelling
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agent. Suitable materials for forming the hollow, flexible members of the
present invention include, but are not limited to, silk; rayon; a nylon;
cellulose;
a polyvinyl material; a polyolefin material; a linen; a polypropylene; a
permeable plastic material; any derivatives thereof; any copolymers thereof;
and any combinations thereof.
Suitable permeable plastic materials may
include, but are not limited to, polyethylene; monochlorotrifluoroethylene;
rubber hydrochloride; a fluoropolymer; a polyamide; polyethersulphone;
polyethylene terephthalate; polyetheretherketone; copolymers thereof;
derivatives thereof; and any combination thereof.
[0031] In some embodiments, the hollow, flexible members of the
present invention further comprise an adhesion agent. The adhesion agent is
typically located on the outer face of the hollow, flexible member. As used
herein, the term "outer face" refers to the portion of the hollow, flexible
members that is capable of contacting other hollow, flexible members (e.g.,
the
portion that does not house the swellable particles of the present invention).
The adhesion agent may act to encourage individual encased swelled fluid loss
particles (after the swellable particles have swelled) to form an entangled
mass.
The adhesion agents may be particularly useful when a rigid swellable particle
is
used in accordance with the teachings of the present invention or when
particularly linear shaped hollow, flexible members are used. The adhesion
agent may be any type of fastener or projection that may aid in contacting one
or more encased swelled fluid loss particles together. Suitable adhesion
agents
may include, but are not limited to, a hook and loop fastener; a loop; a pin;
a
clip; a wire; a magnet; a hook; a tether; a sticky coating; a textured fabric;
and
any combinations thereof. In some embodiments, multiple adhesion agents are
included on a single hollow, flexible member. The multiple adhesion agents may
be of the same type or of different types.
[0032] In some embodiments, particulates may be included with the
swellable particles of the present invention and introduced together into the
wellbore in the subterranean formation. The particulates may synergistically
interact with the swellable particles so as to enhance the sealing capacity of
a
fluid loss zone. That is, if any interstitial spaces exist within, for
example, an
entangled mass composed of swellable particles, the particulates may fill
those
voids. Although it is not necessary to include particulates in the methods of
the
present invention, it may be preferred when particularly large vugular or
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cavernous fluid loss zones require controlling. The particulates for use in
the
present invention may be any particulates suitable for use in a hydrocarbon
operation and may include, for example, proppant particulates, traditional
FLCM
particulates, and the like.
[0033] Suitable materials for the particulates of the present invention
may include, but are not limited to, sand; ground marble; acid soluble solids;
bauxite; ceramic materials; glass materials; polymer materials;
polytetrafluoroethylene materials; nut shell pieces; cured resinous
particulates
comprising nut shell pieces; seed shell pieces; cured resinous particulates
comprising seed shell pieces; fruit pit pieces; cured resinous particulates
comprising fruit pit pieces; wood; composite particulates; and any combination
thereof. Suitable composite particulates may comprise a binder and a filler
material wherein suitable filler materials includes, but is not limited to,
silica;
alumina; fumed carbon; carbon black; graphite; mica; titanium dioxide; meta-
silicate; calcium silicate; kaolin; talc; zirconia; boron; fly ash; hollow
glass
microspheres; solid glass; and any combination thereof.
[0034] The swellable particles and/or the particulates of the present
invention may be introduced into a wellbore in a subterranean formation in any
treatment fluid that may be used in a hydrocarbon well operation for
controlling
a fluid loss zone. Suitable treatment fluids for use in conjunction with the
present invention may include, but are not limited to, oil-based fluids;
aqueous-
based fluids; aqueous-miscible fluids; water-in-oil emulsions; or oil-in-water
emulsions. Suitable oil-based fluids may include alkanes; olefins; aromatic
organic compounds; cyclic alkanes; paraffins; diesel fluids; mineral oils;
desulfurized hydrogenated kerosenes; and any combination thereof. Suitable
aqueous-based fluids may include fresh water; saltwater (e.g., water
containing
one or more salts dissolved therein); brine (e.g., saturated salt water);
seawater; and any combination thereof. Suitable aqueous-miscible fluids may
include, but are not limited to, alcohols; (e.g., methanol, ethanol, n-
propanol,
isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol); glycerins;
glycols (e.g., polyglycols, propylene glycol, and ethylene glycol); polyglycol
amines; polyols; any derivative thereof; any in combination with salts (e.g.,
sodium chloride, calcium chloride, calcium bromide, zinc bromide, potassium
carbonate, sodium formate, potassium formate, cesium formate, sodium
acetate, potassium acetate, calcium acetate, ammonium acetate, ammonium
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chloride, ammonium bromide, sodium nitrate, potassium nitrate, ammonium
nitrate, ammonium sulfate, calcium nitrate, sodium carbonate, and potassium
carbonate); any in combination with an aqueous-based fluid; and any
combination thereof. Suitable water-in-oil emulsions, also known as invert
emulsions, may have an oil-to-water ratio from a lower limit of greater than
about 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to an upper limit of
less than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35 by
volume in the base fluid, where the amount may range from any lower limit to
any upper limit and encompass any subset therebetween. Examples of suitable
invert emulsions include those disclosed in U.S. Patent Nos. 5,905,061
entitled
"Invert Emulsion Fluids Suitable for Drilling" filed on May 23, 1997;
5,977,031
entitled "Ester Based Invert Emulsion Drilling Fluids and Muds Having Negative
Alkalinity" filed on August 8, 1998; 6,828,279 entitled "Biodegradable
Surfactant
for Invert Emulsion Drilling Fluid" filed on August 10, 2001; 7,534,745
entitled
"Gelled Invert Emulsion Compositions Comprising Polyvalent Metal Salts of an
Organophosphonic Acid Ester or an Organophosphinic Acid and Methods of Use
and Manufacture" filed on May 5, 2004; 7,645,723 entitled "Method of Drilling
Using Invert Emulsion Drilling Fluids" filed on August 15, 2007; and 7,696,131
entitled "Diesel Oil-Based Invert Emulsion Drilling Fluids and Methods of
Drilling
Boreholes" filed on July 5, 2007. It should be noted that for water-in-oil and
oil-
in-water emulsions, any mixture of the above may be used including the water
being and/or comprising an aqueous-miscible fluid.
[0035] Embodiments disclosed herein include Embodiment A and
Embodiment B.
[0036] Embodiment A: A method of treating a fluid loss zone in a
wellbore in a subterranean formation comprising: providing swellable particles
having an initial unswelled volume, wherein the swellable particles upon
swelling
adopt a specific shape; introducing the swellable particles into the wellbore
in
the subterranean formation; and swelling the swellable particles so as to
adopt a
swelled volume beyond the initial unswelled volume; and sealing at least a
portion of the fluid loss zone.
[0037] Embodiment A may have one or more of the following additional
elements in any combination:
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[0038] Element A1: The method wherein particulates are introduced
into the wellbore and interact with the swellable particles upon swelling to
perform the step of sealing at least a portion of the fluid loss zone.
[0039] Element A2: The method wherein the initial unswelled volume of
the swellable particles is capable of increasing by up to about 400% to adopt
the
swelled volume.
[0040] Element A3: The method wherein the initial unswelled volume of
the swellable particles is less than about 15 mm in diameter.
[0041] Element A4: The method wherein the shape adopted by the
swellable particles upon swelling is selected from the group consisting of
spherical-shaped; cubic-shaped; rod-shaped; rectangle-shaped; cone-shaped;
ellipse-shaped; cylinder-shaped; polygon-shaped; pyramid-shaped; torus-
shaped; cross-shaped; lattice-shaped; star-shaped; crescent-shaped; bowtie-
shaped; semicircle-shaped; spiral-shaped; and any combination thereof.
[0042] Element A5: The method wherein the swellable particles are
formed from the group consisting of a swellable polymer; a salt of swellable
polymeric material; and any combination thereof.
[0043] Element A6: The method wherein the swellable particles are
formed from the group consisting of a swellable polymer; a salt of swellable
polymeric material; and any combination thereof and wherein the swellable
particles are formed from the coextrusion of at least two of a swellable
polymer;
a salt of swellable polymeric material; and a non-swellable polymer.
[0044] Element A7: The method wherein the swellable material is
water-swellable; oil-swellable; or a combination thereof.
[0045] By way of non-limiting example, exemplary combinations
applicable to Embodiment A include: Embodiment A with Elements A1 and A3;
Embodiment A with Elements A2, A4, and A6; Embodiment A with Elements A1,
A2 and A5; etc.
[0046] Embodiment B: A method of treating a fluid loss zone in a
wellbore in a subterranean formation comprising: providing a hollow, flexible
member having at multiple ends and a shape; providing a swellable particle
having an initial unswelled volume; placing the swellable particle into a
first
portion of the hollow, flexible member, while leaving a second portion empty;
collapsing the second portion of the hollow, flexible member around the
swellable particle so as to form a collapsed swellable particle having a
volume
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approximately equivalent to the initial unswelled volume of the swellable
material; introducing the collapsed swellable particle into the wellbore in
the
subterranean formation; and swelling the swellable particle so as to adopt a
swelled volume beyond the initial unswelled volume, wherein the swelling of
the
swellable particle causes the swellable particle take the shape of the hollow,
flexible member so as to form an encased swelled fluid loss particle; and
sealing
at least a portion of the fluid loss zone.
[0047] Embodiment B may have one or more of the following additional
elements in any combination:
[0048] Element B1: The method wherein at least one of the multiple
ends of the hollow, flexible member is a closed end and the step of placing
the
swellable material into a first portion of the hollow, flexible member
comprises
placing the swellable particle so as to substantially abut the closed end.
[0049] Element B2: The method wherein the shape of the hollow,
flexible member has an approximate center portion and the step of placing the
swellable material into a first portion of the hollow, flexible member
comprises
placing the swellable particle substantially in the center portion.
[0050] Element B3: The method wherein particulates are introduced
into the wellbore and interact with the encased swelled fluid loss material to
perform the step of sealing at least a portion of the fluid loss zone.
[0051] Element B4: The method wherein the initial unswelled volume of
the swellable particle is capable of increasing by up to about 400% to adopt
the
swelled volume.
[0052] Element B5: The method wherein the hollow, flexible member is
comprised of a material having a tensile strength of at least 10 MPa.
[0053] Element B6: The method wherein the hollow, flexible member is
comprised of a material selected from the group consisting of silk; rayon; a
nylon; cellulose; a polyvinyl material; a polyolefin material; a linen; a
polypropylene; a permeable plastic material; any derivatives thereof; and any
combinations thereof.
[0054] Element B7: The method wherein the initial unswelled volume of
the swellable particle is less than about 15 mm in diameter.
[0055] Element B8: The method wherein the hollow, flexible member
further comprises an adhesion agent.
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[0056] Element B9: The method wherein the hollow, flexible member
further comprises an adhesion agent and wherein the adhesion agent is selected
from the group consisting of a hook and loop fastener; a loop; a pin; a clip;
a
wire; a magnet; a hook; a tether; a sticky coating; a textured fabric; and any
combinations thereof.
[0057] Element B10: The method wherein the shape adopted by the
swellable material upon swelling is selected from the group consisting of
spherical-shaped; cubic-shaped; rod-shaped; rectangle-shaped; cone-shaped;
ellipse-shaped; cylinder-shaped; polygon-shaped; pyramid-shaped; torus-
shaped; cross-shaped; lattice-shaped; star-shaped; crescent-shaped; bowtie-
shaped; semicircle-shaped; spiral-shaped; and any combination thereof.
[0058] Element B11: The method wherein the swellable particles are
formed from the group consisting of a swellable polymer; a salt of swellable
polymeric material; and any combination thereof.
[0059] By way of non-limiting example, exemplary combinations
applicable to Embodiment B include: Embodiment B with Elements B1 and B2;
Embodiment B with Elements B2, B4, and B8; Embodiment A with Elements B1,
B3 and B9; etc.
[0060] Therefore, the present invention is well adapted to attain the
ends and advantages mentioned as well as those that are inherent therein. The
particular embodiments disclosed above are illustrative only, as the present
invention may be modified and practiced in different but equivalent manners
apparent to those skilled in the art having the benefit of the teachings
herein.
Furthermore, no limitations are intended to the details of construction or
design
herein shown, other than as described in the claims below. It is therefore
evident that the particular illustrative embodiments disclosed above may be
altered, combined, or modified and all such variations are considered within
the
scope and spirit of the present invention. The invention illustratively
disclosed
herein suitably may be practiced in the absence of any element that is not
specifically disclosed herein and/or any optional element disclosed herein.
While
compositions and methods are described in terms of "comprising," "containing,"
or "including" various components or steps, the compositions and methods can
also "consist essentially of" or "consist of" the various components and
steps.
All numbers and ranges disclosed above may vary by some amount. Whenever
a numerical range with a lower limit and an upper limit is disclosed, any
number
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and any included range falling within the range is specifically disclosed. In
particular, every range of values (of the form, "from about a to about b," or,
equivalently, "from approximately a to b," or, equivalently, "from
approximately
a-b") disclosed herein is to be understood to set forth every number and range
encompassed within the broader range of values. Also, the terms in the claims
have their plain, ordinary meaning unless otherwise explicitly and clearly
defined
by the patentee. Moreover, the indefinite articles "a" or "an," as used in the
claims, are defined herein to mean one or more than one of the element that it
introduces.
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